Process to Maximize Methane Content in Natural Gas Stream

ABSTRACT

The present invention relates to a hydrogenolysis process and catalyst for conversion of ethane to methane in a natural gas stream when such streams contain large quantities of ethane. Such natural gas streams include the product of the in situ treatment of oil shale to produce oil and gas. Hydrogenolysis catalysts have been identified that produce high yields of ethane at low light-off temperatures.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a Continuation-in-Part of copending application Ser. No. 11/322,411 filed Dec. 30, 2005, the contents of which are hereby incorporated by reference in its entirety.

FIELD OF THE INVENTION

The present invention relates to a process for enhancement of methane content in a natural gas stream. More particularly, the present invention relates to a hydrogenolysis process and catalyst for conversion of ethane to methane in a natural gas stream when such streams contain large quantities of ethane.

The composition of natural gas that will be sent into a pipeline must adhere to a large number of specifications to ensure proper operation of downstream equipment that uses it. The energy value of the gas, normally expressed in BTU's is an important criterion. The maximum allowable BTU value of the gas varies between 1180 and 1060 BTU/scf, depending on the pipeline and the country it is in. In some locations, the composition of the natural gas stream needs considerable treatment to meet these criteria.

Ever since the commercial use and production of liquid hydrocarbons commenced in the mid-19th century, scientists have pursued ways of economically extracting hydrocarbons from organic-rich rocks such as oil shale. Historically and currently, almost all hydrocarbons are produced from subterranean reservoir strata and formations. Such hydrocarbon-bearing reservoirs, containing natural gas and/or oil, typically comprise permeable and porous rock such as sandstone or limestone (carbonate). Frequently, these types of rocks serve as traps for hydrocarbons and can be commercially exploited as oil or gas reservoirs. Once penetrated by a well, reservoir strata may be able to produce hydrocarbons in commercial quantities.

Reservoir strata and formations such as sandstone and carbonate are not, however, the original source of the hydrocarbons. The reservoirs are usually the rocks into which the hydrocarbons have migrated over geologic time. The precursors to these reservoirs are the organic-rich rocks from which the hydrocarbons originally derive. A common organic-rich source rock is shale which contains a hydrocarbon precursor known as kerogen. The kerogen is a complex organic material that is the product of the initial biologic organic matter that was buried with the soils and clays which ultimately formed the shale rocks. The kerogen is generally tightly bound within the rock and only releases hydrocarbons when it is exposed to temperatures over 100° C., typically under deep burial. This process is extremely slow and normally takes place over thousands or millions of year's time. Eventually, under the right conditions, the hydrocarbons within the shale or other source rocks will migrate (often through natural fissures, fractures and faults) until they reach a reservoir trap such as a sandstone or carbonate formation.

Source rocks that have yet to liberate their kerogen in the form of hydrocarbons are known as “immature” source rocks. These immature source rocks, however, contain the overwhelming majority of buried organic matter in the earth's crust. It is estimated that less than 1% of the organic matter is in the form of is hydrocarbons contained in reservoir rocks. The great majority is still present as kerogen and thus represents a vast untapped energy source.

Unfortunately, kerogen is not readily liberated from shale or other source rocks. Kerogen-bearing rocks near the surface can be mined and crushed and, in a process known as retorting, the crushed shale can then be heated to high temperatures which convert the kerogen to liquid hydrocarbons. Commercial and experimental mining and retorting methods for producing hydrocarbons from shale have been conducted since 1862 in various countries around the world. In the 1970s and 1980s several oil companies conducted pilot plant shale oil operations in the Piceance Basin of Colorado where large, high-quality reserves of oil shale are located. There are a number of drawbacks to surface production of shale oil which has made its production more costly compared to conventional hydrocarbon production.

One solution to the high costs associated with surface shale oil production and the problems involved in trying to mine shale that is located at depths too deep to mine, is to produce shale oil using in situ processes. In situ processing eliminates the costs associated with the mining, crushing, handling and disposal of the shale rock. In the in situ process, the oil shale can first broken into large fragments with explosives and then the kerogen is subjected to in situ heating. The heating may be a combustion process or by another method of introducing heat underground such as steam injection or by air injection into the shale formation. The end result is the production of a product that on an energy basis is about two-thirds liquid with about one-third being a gas similar to natural gas. There will be some variation in composition, but the gas product comprises methane, ethane, propane, higher carbon hydrocarbons, hydrogen, carbon dioxide and carbon monoxide. This gas product stream may contain substantially higher percentages of ethane and propane than in a typical natural gas stream. This composition poses new challenges for gas composition adjustment to the pipeline specification.

Several techniques have been proposed to reduce the caloric value of a rich gas that contains up to 30 vol-% combined ethane and propane. They range from the addition of nitrogen or air to the removal of higher hydrocarbons, by condensation. The addition of nitrogen requires the construction of an air separation plant on site, while the selective removal of the heavier hydrocarbons generates an LPG or NGL product stream. In certain cases, the value associated with such a hydrocarbon side-stream is significant, due to co-location of the gas conditioning plant with other chemical processing plants (such as ethane cracker) or a convenient outlet for liquid fuels.

In other cases however, the side product is of little value, as the producer has no viable means to bring it to the market due to remote location, capital expenditure of conversion process, or lack of interest in making chemicals. The latter case results in atypical economics: higher hydrocarbons are only valued at local fuel value, where as methane can be sold at a higher natural gas value in the market. In a typical gas stream from an in situ process, the gas comprises about 20-25% by volume ethane (including a small volume propane). In some locations it will be feasible to separate the ethane from the methane and then dehydrogenate the ethane to produce ethylene. However, in some locations it is not practical to produce ethylene and products such as polyethylene. In such locations, it is highly desirable to be able to transport this ethane in the natural gas pipeline. The present invention provides an inexpensive process to achieve this goal.

SUMMARY OF THE INVENTION

We have now invented a method for adjusting the composition of natural gas or other methane containing stream prior to entry into the pipeline. The technique makes use of the available hydrogen in the feed to convert the higher hydrocarbons (especially ethane), as well as the carbon oxides, into methane, through catalytic hydrogenolysis and other reactions. While it is envisioned that the catalytic steps required can be carried out in a single reactor, it may be desirable to use separate reactors operating at different conditions to optimize the catalytic performances for the various steps required, such as olefin saturation, COx hydrogenation and light paraffin hydrogenolysis. The process of the present invention comprises a process for increasing methane content in a natural gas feed stream or a similar feed stream comprising providing a gaseous feed stream comprising a first quantity of methane, ethane, and hydrogen and sending the gaseous feed stream to a conversion unit wherein a hydrogenolysis reaction takes place wherein said natural gas feed stream is contacted with at least one hydrogenolysis catalyst at a temperature and pressure sufficient to substantially convert said ethane to a second quantity of methane. Further separation of the methane from any other components may be required to form a purified natural gas feed stream. In addition, a methanation reaction may be a part of the process to increase the methane content while reducing the carbon dioxide and hydrogen content. To the extent that there are higher hydrocarbons than ethane (such as propane), these hydrocarbons are also substantially converted to methane by the hydrogenolysis reaction.

The gaseous feed stream may contain 6 to 30 vol-% combined ethane and propane, preferably from 10 to 25 vol-% ethane and propane and most preferably from 20 to 25 vol-% combined ethane and propane.

The hydrogenolysis of ethane process is shown by the following equation:

H₂+C₂H₆→2CH₄.

Preferred catalytic materials for this purpose are transition metals (particularly nickel, cobalt, osmium, iridium, rhodium, ruthenium and rhenium) supported on metal oxide supports. In the case of nickel and cobalt, the metal is present in a relatively high concentration on the support due to a lower activity level (>5 wt-%), while the more active but much more expensive ruthenium and rhodium catalysts use lower levels of metals (<1 wt-%). The hydrogenolysis reaction has a light off temperature below which catalyst activity is very low (under 20% conversion) and above which where ethane conversion to methane can be more than 90%. A catalyst with a low light-off temperature is preferred in that it saves energy by reducing the amount of preheating of feed that is required. Preferred supports include alumina, silica, zirconia, titania, other metal oxides and their mixtures. A theta form of alumina was found to be a particularly preferred support material. The invention further consists of flow schemes for implementation of the invention and integration with existing components.

DETAILED DESCRIPTION OF THE INVENTION

In the present invention, the enhancement of the methane content in a natural gas stream has been found to be achievable through the catalytic hydrogenolysis of paraffins by the following general reaction:

C_(n)H_(m)+(4n−m)/2H₂ =nCH₄.

The predominant paraffin to be converted to methane found in the natural gas streams is ethane. The combined volume percent of ethane plus propane may range from about 6 to 30 vol-%, preferably from 10 to 25 vol-% and most preferably from 20 to 25 vol-%. This reaction is exothermic and will therefore be limited in conversion at higher temperatures. Optimizing kinetics vs. extent of conversion, the preferred temperature range for this conversion will be 250° to 600° C. Depending on the actual composition of the gas, some means may need to be employed to reduce the adiabatic temperature rise. A relatively cheap method to accomplish this is the use of interbed quenches, using the cold feed. In one embodiment of the present invention, the feed can be divided into two or more portions with a first portion sent through the hydrogenolysis reaction and then mixed with a remaining portion of feed before the combined feed is sent again through a hydrogenolysis reaction. The effect of pressure on the rate of conversion is substantial. The reaction will preferably be run at either the well pressure or the pipeline pressure.

A useful catalytic system in the present invention is reduced nickel supported on a refractory metal oxide, such as alumina. The catalyst can be prepared as supported NiO that is reduced in situ with H₂ prior to use. Conditions for the hydrogenolysis of light paraffins, such as ethane, to methane are 250° to 600° C. (preferably 300° to 400° C.), 0 to 500 total psig (preferably 10 to 50 psig ethane partial pressure), 0.1 to 1000 hr⁻¹ WHSV (preferably 0.5 to 5 hr⁻¹) and a H₂ to hydrocarbon molar feed ratio that can be as low as sub-stoichiometric at 0.8 moles of hydrogen to each mole of ethane and where complete conversion of ethane is sought preferably 2 to 5 times stoichiometric since some of the hydrogen may react with carbon oxides in the stream to produce methane. The feed will likely include other components, in particular methane, CO and CO₂. Other potential catalysts for catalyzing the hydrogenolysis reaction include supported Co, Ru, Rh, Os, Ir, Re and Fe.

The gas will also contain the carbon oxides as well as steam. These will most likely be removed prior to entry in the pipeline. It is of interest to note that the carbon oxides can also readily be converted to methane over the same catalyst and conditions described for the hydrogenolysis reaction. Even if both oxides are not converted directly to methane, the water gas shift reaction, which is also catalyzed by the catalysts and conditions proposed for hydrogenolysis, will rapidly equilibrate any CO/CO₂ ratio according to the following formulas:

Methanation reaction: CO+3H₂=CH₄+H₂O

Water gas shift reaction: CO+H₂O=CO₂+H₂

Depending on the amount of hydrogen available in the feed, the conversion of the higher hydrocarbons and the conversion of the carbon oxides may both be feasible. In doing so though, more water is formed as a side product, putting an additional load on the gas driers. The following table shows an example of a feed treated in accordance with the present invention with the pipeline specification and the predicted composition of a treated stream. The stream's methane content is increased by a very significant 50%. The feed and predicted values may not total exactly 100% due to rounding of values.

Vol-% Feed Pipeline Spec Predicted H₂ 19.6 0.1 0.01 CH₄ 56 n/a 94.2 C₂ 21 C2 + C3 <3.7 1.5 C₂═ 0.2 (low) .04 C₃ 1.5 C2 + C3 <3.7 1.1 C₃═ 0.1 (low) 0.5 CO 0.5 (low) 0.53 CO₂ 0.0 Non hydrocarbon total <3 vol-% 0.9 N₂ 1.3 Non hydrocarbon total <3 vol-% 1.2 H₂S <10 ppmv (low) <0.1 ppmv Water Dry <5 lbs/MM scf on spec

In a prior art process, the following separation and purification steps take place. Upon separation of the produced crude and associated gas (this will be done in a number of steps at different pressures), the crude oil is sent down its pipeline, while the gas composition undergoes further adjustment. Upon desulphurization of the gas, the gas typically passes through a demethanizer to remove the methane and hydrogen. The bottoms of this column are then led to a de-ethanizer, where ethane and ethylene are separated from a potential LPG product. From the demethanizer, methane and hydrogen are split. Hydrogen can be sold as a by-product; the methane is the main product on the gas side and is sent down the pipeline. The ethane can be dehydrogenated to produce ethylene.

In one embodiment of the present invention, an ethane conversion step is integrated into the process. This scheme takes the C₂ stream from the de-ethanizer, and part of the hydrogen product to a converter in which a hydrogenolysis reaction takes place. The ethane and hydrogen streams are preheated to a temperature of about 300° to 350° C. and led into the converter. The ethane is substantially converted to methane, with at least 50%, more preferably over 90% and as much as 99% or even more of the ethane converted to methane. The effluent of the converter is cooled in the F/E exchanger, cooled further against cooling water, potentially chilled further and sent back to the hydrogen/methane separation column. Note that the conversion needs to be such that the BTU value of the stream coming out of the bottom of the hydrogen/methane separator does not exceed the pipeline specification.

In another embodiment of the invention, instead of separating out and processing the ethane separately, the whole gas stream is mixed with a recycle stream and fed into the conversion reactor. This processing of the complete stream avoids the expense of including a deethanizer in the design which would add a significant energy cost for refrigeration. Larger reactors are required due to the increase in the volume processed, but this embodiment reduces the adiabatic temperature rise over the conversion significantly and makes the reactor simpler and cheaper. The product exiting this reactor may still has a relatively high hydrogen concentration due to excess hydrogen present for the hydrogenolysis reaction and would require further product separation. Typically, a membrane unit can be used to produce a product gas stream low in hydrogen and a corresponding stream high in hydrogen content. In some designs a lower amount of hydrogen is used which allows for this step to be unnecessary.

Additional control of the temperature can be achieved by splitting the gas stream into two or more streams prior to entering the hydrogenolysis converter units. The first stream is then preheated prior to entering a first converter. Then the second stream acts as a quench stream upon being combined with the first stream that has now exited the first converter. This arrangement can control the reaction temperatures and avoid the need for any auxiliary cooling. This is important as the reactions involved are equilibrium limited and as the equilibrium constant is strongly temperature dependent in the range of operation considered here. The temperature at the exit of Converter 2 should preferably not exceed 470° C. and is preferably lower.

Control of the hydrogen content within the stream can also be achieved by employing a methanation step in which the carbon oxides react with hydrogen to produce additional methane. One way that this can be achieved is by adding a CO₂ stream to the stream higher in hydrogen content after using the membrane to produce a methane stream and a hydrogen concentrated stream and after this addition, performing a selective methanation. In one example of the use of such selective methanation the raw feed is no longer combined with a recycle stream but is still split into 2 streams. The ratio between the two streams is controlled such that the exit of the second converter is a temperature between 450° and 500° C., and preferably in the lower part of this range. Upon exiting the second Converter, CO₂ is blended into the stream and a selective methanation is performed in a finishing reactor. Heat exchange with an incoming gas feed or other cooling source may be required to bring the feed temperature to this finishing reactor down to 300° to 350° C. The adiabatic temperature rise in the finishing vessel will be minimal. In the optimum case of sub-stoichiometric hydrogen mentioned above, the temperature increases by some 2° C. The effluent after the methanation reaction is then taken to a CO₂ removal unit to be brought down to natural gas pipeline specification level for CO₂ using common technology such as solvent separation systems, an adsorption process or a CO₂ selective membrane. The CO₂ recovered from that separation can be recycled to an earlier point in the process where it can undergo methanation to further enhance the methane content to the natural gas pipeline.

The following discussion concerns the catalysts that have been found useful in the present invention. The initial experiments used a commercial nickel on attapulgite clay catalyst. The experimental conditions were a 400 psig, 1 hr⁻¹ C₂H₆ weight hourly space velocity (WHSV) and molar feed ratios of hydrogen/ethane of 2/1 and 4/1. The presence of a light-off temperature could be clearly seen. The initial molar feed ratio of hydrogen/ethane was 2/1. Initially it was found that increasing the temperature from 300° to 335° C. increased conversion to only about 12%. An additional increase of temperature to 340° C. resulted in a dramatic increase in conversion to over 95%. The high level of conversion was lost when the hydrogen feed rate was doubled to provide a 4/1 hydrogen/ethane molar feed ratio. However, it was found that a further temperature increase of just 10° to 350° C. was sufficient to restore conversion from ethane to methane to over 95%. It was found that once high conversion was restored, the reactor block temperature could be reduced by 10° C. without a substantial change in the level of conversion.

A second laboratory plant test was conducted at a lower pressure of 50 psig using the same nickel/clay catalyst as above. At a 1 hr⁻¹ C₂H₆ WHSV and 2/1H₂/C₂H₆ molar feed ratio a light-off phenomenon was again observed as an inlet temperature of about 340° C. was required to obtain greater than 95% conversion. However, once the reaction exotherm was established in the catalyst bed, the temperature could be lowered to as low as 305° C. without having conversion of ethane fall below 90%. At about 170 hours on stream, the conditions were changed to 2 hr⁻¹ C₂H₆ WHSV and 4/1H₂/C₂H₆ molar feed ratio which required an inlet temperature of about 340° C. to maintain an exotherm on the catalyst bed.

Further tests were performed to screen for catalyst activity using other metals besides nickel. Catalysts consisting of different levels of cobalt, iron, iridium, nickel, rhenium, rhodium and ruthenium were all tested on attapulgite clay, theta alumina and potassium-modified theta alumina supports. Rhodium was found to provide the greatest catalytic activity achieving near 100% conversion of ethane at a 0.5% metal loading. High conversion can also be achieved using higher concentrations of less expensive nickel and somewhat higher temperatures. The lowest light-off temperature of 225° to 275° C. was obtained with rhodium, with the lowest temperature obtained with the highest (2%) metal loading. Iridium and ruthenium at the 0.5 to 2% metal loading levels give light-off temperatures in the 275° to 325° C. range, while nickel at 5 to 25% metal loading levels falls in the 300° to 350° C. range.

In some embodiments of the present invention, a combination of two or more transition metals may be used. For example, a small amount of rhodium catalyst may be used to achieve light-off temperature and a larger amount of nickel catalyst to catalyze the continuing reaction. The four best transition metal catalysts that were tested were rhodium, ruthenium, iridium and nickel. 

1. A process for increasing methane content in a natural gas feed stream comprising: a) providing a gaseous feed stream comprising a first quantity of methane, ethane, propane and hydrogen wherein said ethane and propane comprise about 6 to 30 vol-% of said gaseous feed stream; and b) sending said gaseous feed stream to a conversion unit wherein a hydrogenolysis reaction takes place wherein said natural gas feed stream is contacted with at least one hydrogenolysis catalyst at a temperature and pressure sufficient to substantially convert said ethane to a second quantity of methane.
 2. The process of claim 1 further comprising separating said first quantity of methane and said second quantity of methane from other components within said gaseous feed stream to form a purified natural gas feed stream.
 3. The process of claim 1 wherein said hydrogen and said ethane are present in a molar ratio of about 0.8:1 to 10:1.
 4. The process of claim 1 wherein said feed stream further comprises carbon oxides.
 5. The process of claim 1 wherein said feed stream further comprises higher hydrocarbons than ethane.
 6. The process of claim 1 wherein said hydrogenolysis catalyst comprises at least one transition metal selected from the group consisting of nickel, cobalt, osmium, iridium, rhodium, ruthenium, rhenium and iron on a metal oxide support.
 7. The process of claim 1 wherein said first quantity of methane is separated from said gaseous feed stream before said gaseous feed stream is sent to said conversion unit.
 8. The process of claim 1 wherein at least 50% of said ethane and propane are converted to methane.
 9. The process of claim 1 wherein at least 90% of said ethane and propane are converted to methane.
 10. The process of claim 1 wherein a portion of said CO and CO₂ are converted to methane within said conversion unit.
 11. The process of claim 1 wherein after said hydrogenolysis reaction takes place, carbon oxides are added to a resulting gaseous stream and then the resulting gaseous stream is subjected to a methanation reaction to react said carbon oxides with hydrogen to produce a third quantity of methane.
 12. The process of claim 1 wherein said natural gas feed stream is a product of thermal treatment of oil or carbon containing rocks or sand.
 13. The process of claim 1 wherein said hydrogenolysis reaction has a light-off temperature between about 300° and 375° C.
 14. The process of claim 1 wherein said temperature for conversion of said higher carbon hydrocarbons than methane to methane is from about 2500 to 600° C.
 15. The process of claim 1 wherein said gaseous feed stream comprises about 10 to 25 vol-% combined ethane and propane.
 16. The process of claim 1 wherein said gaseous feed stream comprises about 20 to 25 vol-% combined ethane and propane.
 17. The process of claim 1 wherein said gaseous feed stream is sent to at least two of said conversion units sequentially.
 18. The process of claim 17 wherein said gaseous feed stream is divided into a first gaseous feed stream and a second gaseous feed stream prior to passing to said at least two of said conversion units, said first gaseous feed stream is heated to a hydrogenolysis reaction temperature, then said first gaseous feed stream is sent to a first conversion unit to produce a first enhanced methane stream, then said first enhanced methane stream is cooled upon being mixed with said second gaseous feed stream to form a combined gaseous feed stream, and then said combined gaseous feed stream is sent to a second conversion unit to be converted to a second enhanced methane stream.
 19. The process of claim 1 further comprising sending said gaseous feed stream to a reactor to convert said carbon dioxide and carbon monoxide to methane.
 20. The process of claim 1 wherein said purified natural gas stream is sent into a natural gas pipeline to be transported. 